Automated diversion valve control for pump down operations

ABSTRACT

A system for pump down operations includes a diversion valve unit that is adjustable between a pumping position and a diversion position and a controller coupled to the diversion valve unit. The system further includes a fluid reservoir, a downhole fluid path between the fluid reservoir and a tool downhole, a driving unit in the downhole fluid path for advancing the tool, and a diversion fluid path between a portion of the downhole fluid path downstream of the driving unit and the fluid reservoir or another fluid receptacle. The diversion valve is in the diversion fluid path and the controller automates the diversion valve position for the diversion valve unit based on a monitored wireline speed or a monitored wireline tension for a wireline unit.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is the U.S. National Stage under 35 U.S.C. §371 ofInternational Patent Application No. PCT/US2011/051375 filed Sep. 13,2011, and entitled “Automated Diversion Valve Control for Pump DownOperations” which is hereby incorporated by reference in its entirety.

BACKGROUND

In wellbore drilling operations, a liner or casing may be coupled to theborehole wall to maintain or strengthen the wall. The drilling apparatusis removed and the liner or casing is placed into the wellbore, formingan annular area between the casing string and the formation. A cementingoperation is then conducted in order to fill the annular area withcement. Downhole application of the cement may include the use of plugsor darts to separate the cement from a displacement fluid, to wipe theinside of the casing or liner, and to provide a hydraulic pressureindication that the cement conveyed through the casing or liner has beenfully inserted into the annular area between the casing and theformation. The wellbore is buttressed by the cemented casing.

To produce hydrocarbons from the formation into the wellbore, the wellmay be stimulated by perforating or fracturing operations. Stimulatingthe well in such ways increases hydrocarbon production from the well, asthe perforations or fractures propagated into the formation provideconductivity paths for the formation fluids along which the greatestpossible quantity of hydrocarbons in an oil and gas reservoir can bedrained/produced into the well bore. In some wells, it may be desirableto individually and selectively create multiple fractures along a wellbore at a distance apart from each other. To control the creation ofmulti-zone fractures along the well bore, it may be necessary to cementa casing or liner to the well bore and mechanically isolate thesubterranean formation being fractured from previously-fracturedformations, or formations that have not yet been fractured. To perforatethe casing and fracture the formation, a device may be lowered into thecased wellbore with explosives or charges. Once lowered to the properdepth, the device, such as a perforating gun, is actuated to perforatethe casing and fracture the formation. The pumping operations andperforating operations described are often referred to as “pump-and-pertoperations.” Efforts to improve efficiency of pump-and-pert operationsor other pump down operations are continually being sought.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of exemplary embodiments, reference will nowbe made to the accompanying drawings in which:

FIG. 1 shows an illustrative logging while drilling (LWD) environment;

FIG. 2 a shows an illustrative wireline tool environment;

FIG. 2 b shows a diversion valve in an illustrative wireline toolenvironment in accordance with various embodiments;

FIG. 3 shows a cross-section view of a drilled wellbore in a hydrocarbonformation;

FIG. 4 shows a side view, in partial cross-section, of an embodiment ofplug deployed perforating tool;

FIG. 5 shows an exploded view of the plug deployed perforating tool ofFIG. 4;

FIG. 6 shows a side view of another embodiment of plug deployedperforating tool;

FIG. 7 shows the wellbore of FIG. 3 including an uninstalled casingstring;

FIG. 8 shows the wellbore of FIG. 7 including a rig tree and a launcherfor an embodiment of a plug deployed perforating tool;

FIG. 9 shows the system of FIG. 8 with cement being pumped;

FIG. 10 shows the system of FIG. 9 with a displacement fluid beingpumped to drive the plug deployed perforating tool and the cement;

FIG. 11 shows the system of FIG. 10 with fluid being further displacedto dispose the cement into the casing string and wellbore annulus;

FIG. 12 shows the system of FIG. 11 with fluid being further displacedto dispose the plug deployed perforating tool into a latch down receiverand the cement fully into the casing string and wellbore annulus;

FIG. 13 shows the system of FIG. 12 with the plug deployed perforatingtool being actuated to perforate the casing and/or formation;

FIG. 14 shows the system of FIG. 13 with the perforating tool beingreleased from the plug member and displaced from the perforated zone;

FIG. 15 shows the system of FIG. 14 with a retrieval or fishing toolbeing deployed into the wellbore toward the released perforating tool;

FIG. 16 shows the system of FIG. 15 with the retrieval or fishing toolbeing coupled to the perforating tool;

FIG. 17 shows an alternative system in accordance with the principles ofthe system of FIG. 16 with the perforating tool being actuated multipletimes to perforate additional zones along the wellbore as the retrievalor fishing tool moves the perforating tool toward the surface;

FIG. 18 illustrates a block diagram of a control system for pump downoperations in accordance with various embodiments;

FIG. 19 illustrates a computer system used with pump down operations inaccordance with various embodiments; and

FIG. 20 illustrates a method in accordance with various embodiments.

DETAILED DESCRIPTION

In the drawings and description that follow, like parts are typicallymarked throughout the specification and drawings with the same referencenumerals. The drawing Figures are not necessarily to scale. Certainfeatures of the disclosure may be shown exaggerated in scale or insomewhat schematic form and some details of conventional elements maynot be shown in the interest of clarity and conciseness. The presentdisclosure is susceptible to embodiments of different forms. Specificembodiments are described in detail and are shown in the drawings, withthe understanding that the present disclosure is to be considered anexemplification of the principles of the invention, and is not intendedto limit the disclosure to that illustrated and described herein. It isto be fully recognized that the different teachings of the embodimentsdiscussed below may be employed separately or in any suitablecombination to produce desired results.

In the following discussion and in the claims, the terms “including” and“comprising” are used in an inclusive fashion, and thus should beinterpreted to mean “including, but not limited to . . . ”. Unlessotherwise specified, any use of any form of the terms “connect,”“engage,” “couple,” “attach,” or any other term describing aninteraction between elements is not meant to limit the interaction todirect interaction between the elements and may also include indirectinteraction between the elements described. Reference to up or down willbe made for purposes of description with “up,” “upper,” “upwardly,” or“upstream” meaning toward the surface of the well and with “down,”“lower,” “downwardly,” or “downstream” meaning toward the terminal endof the well, regardless of the wellbore orientation. In addition, in thediscussion and claims that follow, it may be sometimes stated thatcertain components or elements are in fluid communication. By this it ismeant that the components are constructed and interrelated such that afluid could be communicated between them, as via a passageway, tube, orconduit. The various characteristics mentioned above, as well as otherfeatures and characteristics described in more detail below, will bereadily apparent to those skilled in the art upon reading the followingdetailed description of the embodiments, and by referring to theaccompanying drawings.

Disclosed herein are systems and methods for automated monitoring andcontrol of pump down operations. More specifically, the pump rate of apump unit (or units), the line speed for a logging/perforating (L/P)unit, and the line tension for the L/P unit may be automaticallymonitored and a diversion valve may be automatically monitored andcontrolled to enable efficient pump down operations. In at least someembodiments, pump down operations may be based on a predetermined linespeed, a predetermined line tension, or a predetermined pump rate.However, if any of these parameters change during pump down operations,the diversion valve position will be adjusted automatically. Thetechniques disclosed herein improve safety of pump down operations byreducing the risk of pumping the tools off the end of the wirelinecable.

As a specific example, if the monitored line tension surpasses a desiredthreshold, the diversion valve will be adjusted to a diversion position,which causes at least a portion of pumped fluid to flow through a pathother than down the wellbore (i.e., the diversion valve may cause aportion of pumped fluid to be diverted away from the wellbore in thediversion position), to maintain the desired line tension. Thereafter,if the monitored line tension drops below the predetermined threshold,the diversion valve will be adjusted to a pumping position, which causespumped fluid to flow down the wellbore. In some embodiments, in additionto adjusting the diversion valve, line speed may be reduced or the pumprate may be reduced to maintain the desired line tension. However, oneskilled in the art appreciates that the pump rate does not necessarilyneed to be altered since the diversion valve in the diversion positioneffectively decreases the pump rate (i.e., pumped fluid is diverted fromflowing down the wellbore).

The disclosed operations are best understood in the context of thelarger systems in which they operate. Accordingly, an illustrativelogging while drilling (LWD) environment is shown in FIG. 1. A drillingplatform 2 is equipped with a derrick 4 that supports a hoist 6 forraising and lowering a drill string 8. The hoist 6 suspends a top drive34 that is used to rotate the drill string 8 and to lower the drillstring 8 through the well head 12. Sections of the drill string 8 arejoined by collars 7, typically in the form of threaded connectors.Connected to the lower end of the drill string 8 is a drill bit 14.Drilling is accomplished by rotating the bit 14, by use of a downholemotor near the drill bit 14, and/or by rotating the drill string 8.Drilling fluid, termed mud, is pumped by mud recirculation equipment 16through supply pipe 18, through top drive 34, and down through the drillstring 8 at high pressures and volumes to emerge through nozzles or jetsin the drill bit 14. The mud then travels back up the hole via theannulus formed between the exterior of the drill string 8 and thewellbore wall 20, through a blowout preventer (not specifically shown),and into a mud pit 24 on the surface. On the surface, the drilling mudis cleaned and then recirculated by recirculation equipment 16. Thedrilling mud is used to cool the drill bit 14, to carry cuttings fromthe base of the bore to the surface, and to balance the hydrostaticpressure in the rock formations.

The drill string 8 may be any various conveyances, such as a cable,wireline, E-line, Z-line, jointed pipe, coiled tubing, or casing, orliner string, for example. A motor-driven winch and other associatedequipment is supported at the rig floor for extending the work stringinto the wellbore 10. While exemplary operating environments include astationary drilling rig for lowering work strings and tools within aland-based wellbore, one of ordinary skill in the art appreciates thatmobile workover rigs, well servicing units such as coiled tubing units,and the like, could also be used. It should be understood that otheroperational environments are contemplated, such as offshore wells.Although the wellbore 10 of FIG. 1 is shown to have a verticalextension, other wellbores may have a horizontal extension as well.

In at least some embodiments, the drill string 8 comprises loggingcomponents to collect information regarding the environment of thewellbore 10. In wells employing acoustic telemetry for LWD, downholesensors are coupled to an acoustic telemetry transmitter 28 thattransmits telemetry signals in the form of acoustic vibrations in thetubing wall of drill string 8. An acoustic telemetry receiver array 30may be coupled to tubing below the top drive 34 to receive transmittedtelemetry signals. One or more repeater modules 32 may be optionallyprovided along the drill string to receive and retransmit the telemetrysignals. The repeater modules 32 include both an acoustic telemetryreceiver array and an acoustic telemetry transmitter configuredsimilarly to receiver array 30 and the transmitter 28.

A logging tool 26 may be integrated into the bottom-hole assembly nearthe bit 14. As the bit 14 extends the wellbore 10 through theformations, the downhole sensors collect measurements relating tovarious formation properties as well as the tool orientation andposition and various other drilling conditions. The orientationmeasurements may be performed using an azimuthal orientation indicator,which may include magnetometers, inclinometers, and/or accelerometers,though other sensor types such as gyroscopes may be used. In someembodiments, the tool includes a 3-axis fluxgate magnetometer and a3-axis accelerometer. In some embodiments, logging tool 26 may take theform of a drill collar, i.e., a thick-walled tubular that providesweight and rigidity to aid the drilling process.

At various times during the drilling process, the drill string 8 may beremoved from the wellbore 10 as shown in FIG. 2 a. Once the drill stringhas been removed, downhole tool(s) 36 may be inserted into the wellbore10 using a wireline cable 42. One skilled in the art appreciates thatthe wireline cable 42 may further comprise a slickline cable. Forexample, the downhole tool(s) 36 may be for logging and/or for pump downoperations such as pump-and-pert. The wireline cable 42 may includeconductors for transporting power to the tool 36. Conductors of thewireline cable 42 also may enable communications between the tool 36 anda surface control facility 44. In alternative embodiments, wirelesscommunications are implemented between the tool 36 and the surfacecontrol facility 44. The surface control facility 44 operates the tool36 and/or gathers log data or other sensor data from the tool 36.

FIG. 2 b shows a system for pump down operations 900 including adiversion valve 902 in accordance with various embodiments. The system900 comprises a reservoir 904 that may, for example, store adisplacement fluid 905 for use in pump down operations. A pump 906 drawsdisplacement fluid 905 from the reservoir 904. The diversion valve 902may behave similarly to a throttle valve that is closed in a pumpingposition and at least partially open in a diversion position. In otherwords, in the pumping position, the diversion valve 902 enables fluidflow from the reservoir 904 to a wellbore 10 (i.e., through downholefluid path A) and prevents fluid from returning to the reservoir 904(i.e., through diversion fluid path B). Thus, when the diversion valve902 is in the pumping position, the pump rate of pump 906 is applied tothe wellbore 10 and, in particular, to a tool being pumped down thewellbore 10.

In accordance with various embodiments, certain conditions may cause thediversion valve 902 to be adjusted to the diversion position. As aspecific example, if the monitored line tension of a wireline supportinga tool (not shown) in the wellbore 10 surpasses a desired threshold, thefluid pressure applied to the tool should be reduced. Instead ofreducing the pump speed to reduce the fluid pressure applied to thetool, the diversion valve 902 is adjusted to the diversion position (orthrottled forward in the diversion position to increase the flow ratethrough fluid path B). The diversion valve 902 may be controlled by anelectric motor or the like. In the diversion position, the diversionvalve 902 enables at least a portion of the pumped fluid to return tothe reservoir 904 via fluid path B. In some embodiments, fluid line Bmay lead to an alternate fluid receptacle (not shown) other than thereservoir 904. This effectively reduces the fluid pressure applied tothe tool, decreasing the line tension of the wireline.

Similarly, if the monitored line tension of the wireline drops below adesired lower threshold, the diversion valve 902 may be adjusted toreduce the amount of fluid flowing through fluid path B (i.e., throttleback the fluid flow through the diversion valve 902 in the diversionposition to reduce the flow rate through fluid path B) or prevent fluidfrom flowing through fluid path B (i.e., adjust back to the pumpingposition). In accordance with various embodiments, the diversion valve902 may be adjusted to control and maintain a desired line tension onthe wireline without the need to adjust the speed of the pump 906 or thewireline. Thus the number of parameters to be controlled is minimizedwhile preventing pumping tools off the end of the wireline.Additionally, the automated control described herein is accomplishedwithout operators adjusting throttles, drum brakes, and pumps.

Referring to FIG. 3, the wellbore 10 has been drilled from the surface 5into a formation 13 by conventional drilling apparatus (shown in FIG.1). The formation 13 may include multiple layers 45, 46. As shown, thewellbore 10 may include a vertical portion 47, and in some cases adeviated or horizontal portion 48.

FIGS. 4-17 show various tools and operations related to pump downscenarios that may benefit from the automated control techniquesdisclosed. However, the automated control techniques disclosed hereinare not limited to any particular tool or scenario. In FIG. 4, a tool100 (e.g., a version of tool 36 in FIG. 2) is shown. The tool 100 may bealternately referred to as a perforating tool, a plug deployedperforating tool assembly, a pump down plug deployed perforating gun, acement wiper plug and perforation combination tool, or variationsthereof. The pump down plug deployed perforating tool 100 includes anupper retrieval portion 110, an intermediate portion 120 with aperforating or explosive device, and a lower plug portion 130. Othertools, besides tool 100, could alternatively be pumped down. Thedisclosed control technique is applicable to any operation wherehydraulic horsepower (HHP) is used in conjunction with a wirelinestring. HHP is effective for horizontal wells, where the HHP is neededto push the tool string down the hole. This operation may beaccomplished with gauge rings, plugs, perforation guns, plug-and-perfruns, and/or various other logging tools. For some wells, pump downoperations may be utilized instead of tractor or e-coil operations.

In FIG. 5, an exploded view of the plug deployed perforating toolassembly 100 is shown, separating the coupled portions of the assemblyof FIG. 4 for viewing clarity. The upper retrieval portion 110 includesa fishing neck 112. The intermediate portion 120 includes a firing head122 to which the fishing neck 112 is coupled. The firing head 122includes internal control components 124. In some embodiments, theinternal control components 124 include electronics and circuitry havinga timing delay. In some embodiments, the internal control components 124include sensors for receiving a signal from the surface of the well.Coupled below the firing head 122 is a centralizer 126 includingradially extending centralizing members 128. Coupled below thecentralizer 126 is a perforating or explosive device 150 includingperforators 152. In some embodiments, the perforators 152 includeremovable charge carriers. In some embodiments, there are one or moreperforators 152. The gun 150 includes internal communication elementsfor communicating with the control electronics 124 of the firing head122, as well as actuation components for directing the perforators 152.Below the perforating gun 150 is the lower plug portion 130 including areleasable connection 132 coupling the perforating gun 150 to a plug134. The plug 134 includes a latch down receiver 135, a wiper portion136 with wiper elements, and a fluid pressure resistance member 137,such as a swab cup.

An alternative embodiment of a pump down plug deployed perforating gunis shown as a tool 300 in FIG. 6. The tool 300 includes an upperretrieval portion 310 having a fishing neck 312 or other connectionmember. The fishing neck 312 is coupled to a firing head 322 of anintermediate portion 320. The firing head 322 includes ports 323 andinternal control and communication elements for communicating with aperforating gun 350. The perforating gun 350 includes perforators 352.In some embodiments, the gun 350 includes one or more holes includingcharge carriers that make up the perforators 352. In an exemplaryembodiment, there are approximately six holes with diameters in therange of 0.3 to 0.4 inches. A releasable connection 332 couples theperforating gun 350 to a lower plug portion 330 including a pump downplug 334. The plug 334 includes a latch down receiver 338 and wiperelements 336.

FIG. 7 shows various operations related to the plug deployed perforatingtools 100, 300. As shown, a casing or liner string 210 is run into thewellbore 10, including the horizontal portion 48. This creates anannulus 215 with the borehole wall. The end portion 212 of the casingstring 210 includes a latch down landing collar 220 coupled therein andhaving an outer portion 222 and an inner passageway 226 with an innerlatch profile 224. Coupled to the casing string 210 below the landingcollar 220 is a float shoe 230. Known apparatus are used for the processof conveying the casing string 210 into the wellbore 10.

FIG. 8 shows a rig tree 50 configured and installed at the surface 5. Insome embodiments, the rig tree 50 includes a cement manifold or head 60receiving the flow inlet line 58 and a launcher 52 coupled above thecement manifold 60. The launcher 52 includes a chamber 54 receiving thepump down plug deployed tool 100. In exemplary embodiments, the tool 300is stored in the launcher 52 for use as described below. The chamber 54extends into an outlet passageway 56 in the cement manifold 60 thatcommunicates with the interior 214 of the casing string 210.

FIG. 9 shows cement being pumped through the inlet line 58 to create acement slurry flow 64. The cement flow 64 is directed by a valve 66through a bypass line 62 in the cement manifold 60 to bypass the toollauncher 52. The cement flow 64 is directed downward through thepassageway 56 and into the casing 210 to form a column 240 of cementwith a leading portion 242 being moved toward the end portion 212 of thecasing string 210.

FIG. 10 shows displacement fluid being pumped into line 58 and the valve66 is actuated to re-direct a displacement fluid flow 70 through thealternate line 72 toward the upper part of the plug launcher 52. Atapproximately the same time, the plug launcher 52 is opened to releasethe plug deployed perforating tool 100. Known mechanisms for opening theplug launcher 52 and releasing the tool 100 are included in the system.The displacement fluid flow 70 ejects the tool 100 from the launcherchamber 54 and displaces the tool 100 downward through the passageway 56and into the casing 210. A column 250 of pumped displacement fluid nowdrives the tool 100 and the leading cement column 240 through theinterior of the casing string 210.

In FIG. 11, the displacement fluid flow 70 is continued by pumping,thereby pumping the tool 100 and the cement column 240 further into thecasing string 210 in the horizontal portion 48. The cement 240 passesthrough the passageway 226 in the landing collar 220 and through acentral passageway 232 in the float shoe 230. After exiting the floatshoe 230, the cement slurry is re-directed into the annulus 215 and backup through the wellbore portion 30. The tool 100 is displaced by fluidpressure acting on the pressure member 137 in the plug 134. As the tool100 is displaced through the casing string 210, the wiper element 136cleans the interior surface of the casing string 210.

In FIG. 12, the pumped flow 70 continues to displace the fluid 250, thetool 100, and the cement 240 until the tool 100 arrives at the landingcollar 220. The landing collar 220 receives the lower plug portion 134of the tool 100 and the latch down receiver 135 latches into the landingcollar profile 224. The pumped cement 240 has now filled the annulus 215in both the horizontal portion 48 and the upper vertical portion 47 ofthe wellbore 10. In some embodiments, landing of the latch down pluginto the landing collar will provide a pressure signal at the surface.In some embodiments, the signal is an indication to stop pumping of thedisplacement fluid, test the casing, provide a surge back, wait for thecement to set, or any combination thereof.

After the cement has set, the perforating gun portion 150 of the plugdeployed tool 100 is available for operation. In FIG. 13, theperforating gun 150 is fired by the firing head 122. The charges,explosive devices, or other perforating means in the perforating gun 150are directed into and through the casing and formation to form theperforations or fractures 155. In some embodiments, the controlcircuitry and memory 124 of the firing head 122 are configured at thesurface with a timing delay. The timing delay can be started at any timeduring the above described cementing process and before perforation.Once started, the timer is pre-set to allow for the displacement processof the tool 100 and the cement, as well as the setting time for thecement. At the end of the timing delay, the firing head is triggeredinternally to initiate or actuate the perforating gun 150. In otherembodiments, the control components 124 of the firing head 122 includesensors and other apparatus for receiving a signal from the surface ofthe well. The sensor may be configured to receive a pressure signalinitiated at the surface, or a control signal sent via telemetry orother known means for communicating downhole. Upon receipt of theexternal signal, the firing head 122 is initiated to direct actuation ofthe perforating gun 150.

In FIG. 14, the gun 150 is automatically released at the releasableconnection 132 in response to firing of the gun 150. The releasedconnection 139 is achieved by decoupling the components 132 a, 132 b ofthe connection 132 of the assembled tool 100. The continuous pumping ofthe fluid 70 establishes fluid injection paths 157 through the fractures155 while the engaged latch down plug 134 remains in place.

FIG. 15 shows an additional tool 400 being pumped down the wellbore 10while the pumped fluid 250 continues to inject into the perforations155. In exemplary embodiments, the tool 400 is a retrieval tool with alatch 404 to connect to the fishing neck 112 of the perforating gun 150.In other exemplary embodiments, the tool 400 is another kind of tool. Instill further embodiments, the tool 400 is an additional perforating gunassembly including a first perforating gun 450 with a firing head 452coupled to a second perforating gun 460 with a firing head 462. Thepumped down tool 400 is coupled to the surface via a line 402, which maybe an electric line.

Referring next to FIG. 16, in some embodiments, the additional tool 400with retrieval capabilities is latched onto the released gun 150 bycoupling the latch 404 to the fishing neck 112. The newly combinedassembly 150/400 can now be pulled to the surface by the wireline orelectric line 402. In FIG. 17, the released perforating device 150 hasbeen removed from its deployment plug and being moved toward the surface5. If the tool 400 includes additional perforating devices as taughtherein, additional sets of perforations and fluid injection paths 420,430 can be established by firing the perforating guns as the assembly150/400 is moved up the well.

During the pump down operations described in FIGS. 7-17, automatedmonitoring and control of various operational parameters are performed.In at least some embodiments, the pump rate of a pump unit (or units),the line speed for a logging/perforating (L/P) unit, and the linetension for the L/P unit may be automatically monitored and a diversionvalve, such as the diversion valve 902 shown in FIG. 2 b, may beautomatically monitored and controlled to enable efficient pump downoperations. Monitoring parameters such as the driving force and drivingrate of a driving unit (or units) for advancing the tool into theborehole, the line speed for a wireline unit, and the line tension forthe wireline unit and using those parameters to control a diversionvalve to maintain a desired line tension is useful for any wireline toolin which the tool is driven into the borehole (cased or uncased) andwhere it is desired to not exceed a threshold wireline tension. Forexample, such principles may be applied to any wireline logging tool.

As a specific example, suppose it is desired to run a plug at a linespeed of 425 feet per minute in the vertical portion 47 of wellbore 10and run the plug at a line speed of 375 feet per minute in thehorizontal portion 48 of wellbore 10. Further, suppose the L/P controlunit is always trying to hold 1,000 lbs of tension on tools going in thehole. For this set of desired parameters or L/P variables, the L/Pcontrol unit initially sets the line tension parameter at 1000 lbs andthe line speed parameter at 425 ft/min (for vertical portion 47) andlater 375 ft/min (for horizontal portion 48). In response, the techcontrol center (TCC) automates the diversion valve position and the pumprate to achieve the L/P variables. Once the wellhead is opened and theL/P unit starts down wellbore 10, the TCC sets a diversion valveposition and a pump rate. In some embodiments, the diversion valve isinitially set to the pumping position and the pump rate ramps up to theL/P variables (e.g., within 30 seconds or so). If any of theseparameters change during the pump down operations, the diversion valveposition will be adjusted automatically. The techniques disclosed hereinimprove safety of pump down operations by eliminating the possibility ofpumping the tools off the end of the wireline cable or othercatastrophes. Further, the automated control described herein isaccomplished without operators adjusting throttles, drum brakes, andpumps.

After a well has been cemented and perforated and hydrocarbons have beenextracted from the subterranean reservoir to the extent economicallyviable, it may sometimes be desirable to extract hydrocarbons fromadditional deposits or reservoirs at locations along the casing. Inorder to do so, the casing upstream of the new extraction point has tobe isolated from the existing perforations downstream of the newextraction point. A plug-and-pert tool, similar to those described abovein relation to FIGS. 4 to 6 could be used for such an operation. Insteadof being housed in the launch chamber 54, the tool is pumped orotherwise driven down the casing from the surface, and may be attachedto a wireline cable such as wireline cable 42. The upper and/orintermediate portion of the tool may include a firing head andperforating gun arranged in a similar way to those shown in theembodiments of FIGS. 4 to 6. The tool includes a lower plug portionsimilar to lower plug portions 130 and 330 described above, and mayinclude a pump down plug, similar to plugs 134 and 334 of FIGS. 4 to 6,releasably coupled to the lower plug portion of the tool. In use, thetool is pumped or otherwise driven down the casing to a desired depthwhich is upstream of the existing perforations. Pumping the tool downthe well is possible since the pumping fluid can be displaced into thereservoir from which hydrocarbons have already been extracted throughthe existing perforations. The depth of the tool in the casing may bedetermined by measuring the length of the wireline fed out.

The plug is then deployed to seal off the lower, perforated section ofthe casing from the upstream portion. The plug may be deployed, forexample, in response to a signal transmitted along the wireline, orotherwise via an alternative telemetry system. The plug then actuates orotherwise deploys to engage with the inner wall of the casing to createa seal and isolate the upstream portion of the casing from the lower,perforated section. The perforating gun may then be detonated toperforate the casing and release the perforating gun from the plug, ormay first be released from the plug and moved a desired distanceupstream before being detonated. The perforating gun may be fired by asignal transmitted along the wireline or by a telemetry signal.Alternatively, the perforating gun may be set on a timer, to fire aftera predetermined period of time has elapsed, as described above. Asdescribed above in relation to the tool of FIGS. 14 to 17, such a toolmay include a plurality of perforating guns to create perforations atplural locations along the isolated upstream portion of the casing.Displacement fluid may then be pumped and injected into the formationthrough the newly formed perforations. The contemplated tool is wirelinedeployed, advantageously using the pump down control system describedherein to monitor the pump rate, wireline speed and wireline tension andcontrol a diversion valve. As such, the tool may be easily recovered tothe surface via the wireline after all the perforating guns have beenfired.

FIG. 18 illustrates a block diagram of a control system 500 for pumpdown operations, such as pump-and-perf, in accordance with variousembodiments. The control system components are most usefully located atthe surface, as part of the diversion valve unit, wireline unit, pumpingunit, or as part of a separate remote control unit. Surface controlcomponents facilitate access for maintenance and ensure accurate controlsignal transmission to the diversion valve unit, wireline unit, orpumping unit. However, some or all components of the control system maybe installed on the downhole tool. Such an arrangement may beappropriate where it is desired to integrate the combined controlfunctionality for the diversion valve unit, wireline unit, or pumpingunit into the tool itself (e.g., where the tool may be a separatelyprovided integrated device from the wireline unit and is configured tointerface with the diversion valve unit, the wireline unit, or thepumping unit). In such cases, the tool is ideally provided along with aremote input/output device for monitoring and/or setting controlparameters for the tool/control system from the surface.

As shown, the control system 500 comprises a controller 502 coupled to adiversion valve unit 506. The controller 502 may be additionally coupledto a wireline unit and a pump unit (not shown) to control wireline andpump speeds. The controller 502 may replace the individual controllerusually provided to the diversion valve unit 506 (or one or both of theindividual controllers usually provided to the wireline unit and pumpunit). Alternatively, an entirely separate controller 502 may beprovided that is configured to interface with the existing individualcontrol unit of the diversion valve unit 506.

The controller 502 may be configured to interface with the individualcontrol units of a wide range of existing diversion valve units, pumpingunits, and wireline units, making the controller adaptable to differentvalves and wireline and pumping equipment, including the equipment ofdifferent manufacturers and/or a variety of different wireline tools. Insome applications, the interface between controller 502 and thediversion valve unit 506 may be, for example, wireless (e.g., via WiFior Bluetooth) or over a telephone or internet connection. Appropriatetransmitter/receiver equipment may be connected to the diversion valveunit 506 to permit the controller 502 to interface with it. Thecontroller 502 is thereby able to provide commands to the diversionvalve unit 506 to control a position of a diversion valve during pumpdown operations, such as pump-and-perf operations. Additionally, thecontroller 502 may be configured to provide commands to a wireline unitand/or a pump unit to control wireline movement or pumping during pumpdown operations. This may obviate the necessity for a separate operatorto control the diversion valve unit 506 and the pump down operation mayproceed either entirely automatically under the control of controller502, or with input from a single operator into the controller 502. In atleast some embodiments, the controller 502 relies on control parameters504 (e.g., a diversion valve position parameter, a wireline speedparameter, a wireline tension parameter, and a pump rate parameter) togenerate appropriate commands to the diversion valve unit 506.

Data corresponding to the control parameters 504 are received fromsystem sensors, which are arranged to monitor the respective controlparameters from appropriate locations on the diversion valve unit,pumping unit, wireline unit, and/or wireline tool, or otherwise on thedrilling platform or in the wellbore, and are coupled to the controller502. Pressure also may be monitored by the controller 502 to account forpumping limitations.

In at least some embodiments, a diversion valve position sensor 508, awireline speed sensor 510, a wireline tension sensor 512, and a pumprate sensor 514 provide sensor data to the controller 502. Other sensordata might be relayed to the controller, for example relating to theposition and/or orientation of the wireline tool in the wellbore. Thesensor data from the diversion valve position sensor 508 may corresponddirectly to the position (e.g., throttle position) of the diversionvalve 902 or to data that enables position of the diversion valve 902 orthe fluid flow through the diversion valve 902 to be calculated. Thesensor data from the wireline speed sensor 510 may correspond directlyto wireline speed data or to data that enables the wireline speed to becalculated. The sensor data from the wireline tension sensor 512 maycorrespond directly to wireline tension data or to data that enables thewireline tension to be calculated. The sensor data from the pump ratesensor 514 may correspond directly to pump rate data or to data thatenables the pump rate to be calculated.

During pump down operations, such as pump-and-perf, the controller 502analyzes new sensor data from the sensors 508, 510, 512, 514 and isconfigured to automatically direct the diversion valve unit 506 toadjust the position of the diversion valve 902 in response to changes ina monitored wireline speed and/or monitored wireline tension. In somecases, the controller 502 may automatically direct a pump unit to adjustits pump rate in response to changes in the monitored wireline speedand/or wireline tension and direct a wireline unit to adjust itswireline speed in response to changes in a monitored pump rate.

For example, the controller 502 may direct the diversion valve unit 506to throttle back the diversion valve 902 in a diversion position toreduce a flow rate through the valve 902 (or to adjust the valve 902 toa pumping position) in response to a decrease in the monitored wirelinespeed in order to maintain the speed at which the tool is advanced. Inthis case, it is assumed that the wireline tension is unchanging, orchanging proportional to speed. However, if the wireline tensiondecreases at a non-proportional rate to the rate at which the speeddecreases, this may indicate that the tool is entering debris. In such asituation, the appropriate action would be to throttle forward thediversion valve 902 in the diversion position to increase fluid flowthrough the diversion valve 902 and decrease fluid flow downhole inorder to prevent getting the tool getting stuck. In accordance withvarious embodiments, control of the position of the diversion valve 902based on the wireline speed may also be dependent upon the wirelinetension. In at least some embodiments, comparisons of control parametervalues to predetermined threshold values (e.g., greater than or lessthan comparisons) for diversion valve position, wireline speed, wirelinetension, and pump rate may be considered by the controller 502 inaddition to (or instead of) directional changes (an increase/decrease)for the control parameters.

The controller 502 of may correspond to any of a variety of hardwarecontrollers. In some embodiments, such controller may correspond tohardware, firmware, and/or software systems. As an example, FIG. 19illustrates a computer system 700 used with pump down operations inaccordance with various embodiments. The computer system 700 comprises acomputer 702 with one or more processors 704 coupled to a system memory706. Some embodiments of the computer 702 also include a communicationinterface 726 and I/O devices 728 coupled to the processor 704. Thecomputer 702 is representative of a desktop computer, server computer,notebook computer, handheld computer, or smart phone, etc.

The processor 704 is configured to execute instructions read from thesystem memory 706. The processor 704 may, for example, be ageneral-purpose processor, a digital signal processor, amicrocontroller, etc. Processor architectures generally includeexecution units (e.g., fixed point, floating point, integer, etc.),storage (e.g., registers, memory, etc.), instruction decoding,peripherals (e.g., interrupt controllers, timers, direct memory accesscontrollers, etc.), input/output systems (e.g., serial ports, parallelports, etc.) and various other components and sub-systems.

The system memory 706 corresponds to random access memory (RAM), whichstores programs and/or data structures during runtime of the computer702. For example, during runtime of the computer 702, the system memory706 may store a pump down control application 714, which is loaded intothe system memory 706 for execution by the processor 704.

The system 700 also may comprise a computer-readable storage medium 705,which corresponds to any combination of non-volatile memories such assemiconductor memory (e.g., flash memory), magnetic storage (e.g., ahard drive, tape drive, etc.), optical storage (e.g., compact disc ordigital versatile disc), etc. The computer-readable storage medium 705couples to I/O devices 728 in communication with the processor 704 fortransferring data/code from the computer-readable storage medium 705 tothe computer 702. In some embodiments, the computer-readable storagemedium 705 is locally coupled to I/O devices 728 that comprise one ormore interfaces (e.g., drives, ports, etc.) to enable data to betransferred from the computer-readable storage medium 705 to thecomputer 702. Alternatively, the computer-readable storage medium 705 ispart of a remote system (e.g., a server) from which data/code may bedownloaded to the computer 702 via the I/O devices 728. In such case,the I/O devices 728 may comprise networking components (e.g., a networkadapter for wired or wireless communications). Regardless of whether thecomputer-readable storage medium 705 is local or remote to the computer702, the code and/or data structures stored in the computer-readablestorage medium 705 may be loaded into system memory 706 for execution bythe processor 704. For example, the pump-and-pert control application714 or other software/data structures in the system memory 706 of FIG.20 may have been retrieved from computer-readable storage medium 705.

The I/O devices 728 also may comprise various devices employed by a userto interact with the processor 704 based on programming executedthereby. Exemplary I/O devices 728 include video display devices, suchas liquid crystal, cathode ray, plasma, organic light emitting diode,vacuum fluorescent, electroluminescent, electronic paper or otherappropriate display panels for providing information to the user. Suchdevices may be coupled to the processor 704 via a graphics adapter,keyboards, touchscreens, and pointing devices (e.g., a mouse, trackball,light pen, etc.) are examples of devices includable in the I/O devices728 for providing user input to the processor 704 and may be coupled tothe processor by various wired or wireless communications subsystems,such as Universal Serial Bus (USB) or Bluetooth interfaces.

As shown in FIG. 19, the pump down control application 714 comprisesdiversion valve control instructions 716 and control parameters 720.When executed, the diversion valve control instructions 716 operate togenerate commands for a diversion valve unit 734 coupled to the computer702 via the communication interface 726. In some embodiments, the pumpdown control application 714 also comprises wireline controlinstructions and pump control instructions that, when executed, operateto generate commands for a wireline unit and a pump unit, respectively.The generation of commands by the diversion valve control instructions716 may be based on monitored control parameters 720 such as diversionvalve position, wireline speed, wireline tension, and/or pump rate. Themonitored control parameters 720 may be received during pump downoperations from sensors 732 coupled to the communication interface 726.Alternatively, the sensors 732 provide diversion valve data, wirelinedata and pump data from which the monitored control parameters 720 arecalculated. In either case, the received or derived control parameters720 are stored in the computer 702 for access by the pump down controlapplication 714.

In at least some embodiments, the commands generated by the diversionvalve control instructions 716 for the diversion valve unit 734 causethe diversion valve unit 734 to change the position of the diversionvalve. For example, the diversion valve control instructions 716 maygenerate a throttle forward command to increase fluid flow through thediversion valve unit 734 in response to an increase the monitoredwireline speed and/or an increase in the monitored wireline tension.Alternatively, the diversion valve control instructions 716 may generatea throttle back command to decrease or prevent fluid flow through thediversion valve unit 734 in response to a decrease in the monitoredwireline speed and/or wireline tension. In accordance with variousembodiments, safety thresholds of pump down operations are maintainedwithout the need for monitoring and control from a well operator.

FIG. 20 illustrates a method 800 in accordance with various embodiments.Though shown sequentially for convenience, at least some of the methodsteps may be performed in a different order and/or performed inparallel. Additionally, some embodiments may perform only some of theactions shown. In some embodiments, the operations of FIG. 20, as wellas other operations described herein, can be implemented as instructionsstored in a computer-readable storage medium (e.g., computer-readablestorage medium 705) and executed by a processor (e.g., processor 704).

The method 800 starts by monitoring a wireline speed (block 802) andmonitoring a wireline tension (block 804). The monitoring may beperformed by sensors in communication with a hardware controller or acomputer running software. In some embodiments, pressure and ratesensors could be monitored, if need be, from a transducer and flowmeterin the line rather than from the pump directly. A diversion valveposition for pump down operations is then set based on the monitoredwireline speed and monitored wireline tension (block 806). If changes tocontrol parameters occur during pump down operations (determinationblock 808), the diversion valve position is automatically updated inresponse to the changes (block 810).

In at least some embodiments, the control parameters correspond to themonitored wireline speed and the monitored wireline tension. Forexample, the diversion valve may be throttled forward to divert at leastsome fluid from flowing downhole during pump down operations in responseto a reduction in the monitored wireline speed. The amount that thevalve is throttled forward may correspond to the difference between themonitored wireline speed and a predetermined threshold. The method 800may additionally comprise receiving sensor data and determining thewireline speed and the wireline tension from the sensor data.

The embodiments set forth herein are merely illustrative and do notlimit the scope of the disclosure or the details therein. It will beappreciated that many other modifications and improvements to thedisclosure herein may be made without departing from the scope of thedisclosure or the inventive concepts herein disclosed. Because manyvarying and different embodiments may be made within the scope of theinventive concept herein taught, including equivalent structures ormaterials hereafter thought of, and because many modifications may bemade in the embodiments herein detailed in accordance with thedescriptive requirements of the law, it is to be understood that thedetails herein are to be interpreted as illustrative and not in alimiting sense.

What is claimed is:
 1. A system for pump down operations, comprising: adiversion valve unit adjustable between a pumping position and adiversion position; a controller coupled to the diversion valve unit; afluid reservoir; a downhole fluid path between the fluid reservoir and atool downhole; a driving unit in the downhole fluid path for advancingthe tool; a diversion fluid path between a portion of the downhole fluidpath downstream of the driving unit and the fluid reservoir or anotherfluid receptacle; wherein the diversion valve unit is in the diversionfluid path; and wherein the controller is configured to automaticallyadjust the diversion valve unit between the pumping position and thediversion position based on a monitored wireline speed or a monitoredwireline tension for a wireline unit.
 2. The system of claim 1 whereinin the pumping position, the diversion valve prevents fluid flow throughthe diversion fluid path and in the diversion position, the diversionvalve permits fluid flow through the diversion fluid path.
 3. The systemof claim 2 wherein the controller causes the diversion valve to adjustbetween the diversion position and the pumping position to adjust theflow rate of fluid through the diversion path.
 4. The system of claim 1further comprising a speed sensor in communication with the controller,wherein the controller selectively adjusts the diversion valve positionbased on wireline speed data received from the speed sensor.
 5. Thesystem of claim 1 further comprising a tension sensor in communicationwith the controller, wherein the controller selectively adjusts thediversion valve position based on wireline tension data received fromthe tension sensor.
 6. The system of claim 1 further comprising a speedsensor and a tension sensor in communication with the controller,wherein the controller selectively adjusts the diversion valve positionbased on at least one of wireline speed data received from the speedsensor and wireline tension data received from the tension sensor.
 7. Amethod for pumping a tool with a wireline into a wellbore, comprising:monitoring at least one of a wireline speed and a wireline tension; andautomatically controlling a position of a diversion valve unit based onat least one of the monitored wireline speed and monitored wirelinetension.
 8. The method of claim 7 further comprising receiving sensordata and determining the wireline speed and the wireline tension fromthe sensor data.
 9. The method of claim 7 further comprising controllingthe position of the diversion valve unit to increase the flow ratethrough the diversion valve unit in response to the wireline speed orwireline tension exceeding a predetermined threshold.
 10. The method ofclaim 7 further comprising controlling the position of the diversionvalve unit to decrease the flow rate through the diversion valve unit inresponse to the wireline speed or wireline tension falling below apredetermined threshold.
 11. The method of claim 7 wherein automaticallycontrolling further comprises adjusting the position of the diversionvalve unit between a pumping position and a diversion position, andwherein in the pumping position, the diversion valve unit permits fluidflow solely between a driving unit and a downhole tool and in thediversion position, the diversion valve unit permits fluid flow througha diversion fluid path away from the downhole tool.